Systems and methods for starting, restarting, monitoring, and increasing performance of a production and/or injection system

ABSTRACT

A system includes a distributed control system and a subsea tree that includes subsea tree chokes and a subsea control module communicatively coupled to flow control valves. The distributed control system communicatively couples to the subsea control module, is located at a surface level, and includes processors that send a first instruction to the flow control valves to adjust hydrocarbon production flow when water or gas cut is above a threshold. The processors also send a second instruction to the subsea tree chokes to adjust the flow of the production when a quality of commingling of the production flow with additional production flows is less than a threshold, an arrival pressure is less than a threshold, or an arrival flow rate is less than a threshold. The processors further continue the production of the fluids with current settings when a production rate is above a production rate threshold.

BACKGROUND

This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.

The present disclosure relates generally to starting, restarting, monitoring, and increasing performance of a production and/or injection system. More particularly, the present disclosure relates to a control system that may receive and synthesize information from surface, subsea, and subsurface sensors of the production and/or injection system to control surface, subsea, and subsurface components to effectively start the production and/or injection system. The present disclosure also relates to procedures and methods for using the control system that enable new applications and increased efficiency in operating the production and/or injection system that may not be otherwise available through other technologies.

Oil and gas are produced by hydrocarbon production systems installed on oil and gas fields located either onshore or offshore. To facilitate oil and gas production, injection systems may be combined with the production systems or alternatively installed on the oil and gas fields. Technological advances have enabled producing hydrocarbons from subsea (e.g., deepwater) fields using the production and/or injection systems. A subsea production system may transport hydrocarbons from a subsea reservoir to a delivery point (e.g., on or near the surface).

Portions of a hydrocarbon production system (e.g., oil and gas production systems) and/or an injection system may include electrical assets that may be controlled by a control system. The electrical assets controllable via the control system may enable faster response time when compared to controlling non-electrical (e.g., hydraulic, mechanical, etc.) assets. The control system may enable additional applications and be particularly useful in deep and ultra-deep water field applications. However, traditional subsea production and/or injection systems typically incorporate multiple components (e.g., located at a surface level, a subsea or seafloor level, a subsurface level, etc.) coupled together by multiple, separate control units that may not communicate with one another.

SUMMARY

A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.

A hydrocarbon production system and/or an injection system may be controlled by a control system that at least controls some electrical assets. The control system may couple together multiple surface (e.g., topside), subsea, and/or subsurface control units, applications, and/or components. As such, the control system may access multiple sensors located at surface, subsea, and subsurface locations, to receive a variety of equipment status data, hydrocarbon production data, and/or injection flow data. The control system may also control components of the production and/or an injection system at surface, subsea, and subsurface locations.

Initializing Production

The present disclosure relates generally to starting a production and/or injection system. More particularly, the present disclosure relates to a control system that may receive and synthesize information from surface, subsea, and subsurface sensors of the production and/or injection system to control surface, subsea, and subsurface components to effectively start the production and/or injection system. The control system may be located at a surface level, and may control certain assets to start producing hydrocarbons from a well. In one embodiment, the control system may receive a water cut or gas cut of the production provided by downhole water cut sensors located at multiple zones of the well, and adjust the production flow at the zones where the water cut or the gas cut is above a water cut or gas cut threshold to reduce the water cut or the gas cut. The control system may also receive data regarding a quality of commingling of the production (e.g., with other productions from other wells of the production system) provided by multiphase flowmeters located at a pipeline end manifold commingling the productions, and adjust operation of production assets to control the production flow at one or more subsea trees mounted on the one or more wells or a pipeline end manifold to control commingling the productions and increase the quality of the commingling.

In another embodiment, the control system may also receive an arrival pressure or arrival flow rate (e.g., at the surface level) of production fluids provided by pressure or flow rate sensors at the surface level, and adjust the operation of certain production assets to control the production flow at the one or more subsea trees mounted on the one or more wells or a pipeline end manifold to increase or decrease the arrival pressure or the arrival flow rate. The control system may also receive bottom hole pressure data provided by downhole pressure sensors, and adjust the operation of certain production assets (e.g., a water injection system) to control the bottom hole pressure.

The control system may further receive a rate of production (e.g., at the surface level), and adjust the operation of certain production assets to control the flow of production (e.g., at the surface, subsea, and/or subsurface levels) to increase or decrease the rate of production. In this manner, increased hydrocarbon production using the production and/or injection system and increased life of the production and/or injection system may be realized while reducing negative impacts on pressure in the wells, negative influences on the hydrocarbon reservoir, and preventing plugs from building up in the production and/or injection system.

Restarting Production

The present disclosure also relates generally to restarting a production and/or injection system (e.g., after an unplanned shutdown of the production and/or injection system). For example, shutting down the production and/or injection system and subsequent restartup of the production and/or injection system may result from regular reservoir and production testing, exception handling to operational hazards such as hurricanes, regular maintenance (e.g., because of equipment exchanges), and the like.

More particularly, the present disclosure relates to a control system that may receive and synthesize information from surface, subsea, and subsurface sensors of the production and/or injection system to control surface, subsea, and subsurface components to effectively restart the production and/or injection system. In one embodiments, the control system may receive an indication that production of hydrocarbons from a well has stopped. To restart the production, the control system may then determine a restart setup time for restarting the production from the well. The control system may depressurize a riser and a flowline of the production system. The control system may also preserve a subsea tree (e.g., flush the subsea tree to maintain production flow in the subsea tree) mounted to the well. The control system may further preserve at least one pipeline (e.g., displace live production fluid in the at least one pipeline to maintain production flow in the at least one pipeline) of the production system, which may include the riser and/or the flowline. The control system may also preserve the well (e.g., flush the well to maintain production flow in the well). The control system may then determine whether the restart setup time has elapsed. If the restart setup time has elapsed, the control system may restart the production at the well. In this manner, increased hydrocarbon production using the production and/or injection system and increased life of the production and/or injection system may be realized while reducing negative impacts on pressure in the wells, negative impacts on the hydrocarbon reservoir, and preventing plugs from building up in the production and/or injection system.

Increasing Production

In addition, the present disclosure relates generally to monitoring and increasing performance of a production and/or injection system. More particularly, the present disclosure also relates to a control system that may receive and synthesize information from surface, subsea, and subsurface sensors of the production and/or injection system to control surface, subsea, and subsurface components to effectively monitor and improve performance of the production and/or injection system. In one embodiment, the control system may be located at a surface level and may receive subsea or subsurface information and determine whether a water cut or sand production in the production is above a water cut or sand production threshold. When the water cut or the sand production in the production is above the water cut or sand production threshold, the control system may adjust flow control devices, inflow control devices, and/or chokes to reduce the water cut or the sand production. When the water cut or the sand production in the production is below the water cut or sand production threshold, the control system may determine a flow rate, pressure, and/or temperature, of the production corresponding to increasing the hydrocarbon production.

The control system may then determine whether the measured flow rate, the measured pressure, and/or the measured temperature approximately matches the determined flow rate, pressure, and/or temperature of the production corresponding to increasing the production. The control system may adjust the flow control devices and/or the one or more inflow control devices when the measured flow rate, the measured pressure, and/or the measured temperature does not approximately match the determined flow rate, pressure, and/or temperature, of the production corresponding to increasing the production. The control system may continue the production with current settings when the measured flow rate, the measured pressure, and/or the measured temperature approximately matches the determined flow rate, pressure, and/or temperature of the production corresponding to increasing the production.

In this manner, increased hydrocarbon production using the production and/or injection system and increased life of the production and/or injection system may be realized while reducing negative impacts on pressure in the wells, negative impacts on the hydrocarbon reservoir, and preventing plugs from building up in the production and/or injection system.

Various refinements of the features noted above may be made in relation to various aspects of the present disclosure. Further features may also be incorporated in these various aspects as well. These refinements and additional features may be made individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

Various features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:

FIG. 1 is a schematic diagram of a subsea hydrocarbon production system, in accordance with an embodiment of the present disclosure;

FIG. 2 is a block diagram illustrating control relationships between components of the subsea hydrocarbon production system of FIG. 1, in accordance with an embodiment of the present disclosure;

FIG. 3 is a block diagram of components controlled by a distributed control system of the subsea hydrocarbon production system of FIG. 1, in accordance with an embodiment of the present disclosure;

FIG. 4 is a block diagram of components controlled by a subsea control module of the subsea hydrocarbon production system of FIG. 1, in accordance with an embodiment of the present disclosure;

FIG. 5 is a block diagram illustrating an example of communication routing in the subsea hydrocarbon production system of FIG. 1, in accordance with an embodiment of the present disclosure;

FIG. 6 is a block diagram illustrating informational relationships between components of the production system of FIG. 1, in accordance with an embodiment of the present disclosure;

FIG. 7 is a flowchart of a method for starting the subsea hydrocarbon production system of FIG. 1, in accordance with one or more embodiments of the present disclosure;

FIG. 8 is a flowchart of a method for restarting the subsea hydrocarbon production system of FIG. 1, in accordance with one or more embodiments of the present disclosure; and

FIG. 9 is a flowchart of a method for monitoring and increasing performance of the subsea hydrocarbon production system of FIG. 1, in accordance with one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

One or more specific embodiments will be described below. In an effort to provide a concise description of these embodiments, not all features of an actual implementation are described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

The figures are not necessarily to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness. Although one or more embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. It is to be fully recognized that the different teachings of the embodiments discussed may be employed separately or in any suitable combination to produce desired results. In addition, one skilled in the art will understand that the description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment.

When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “including,” “incorporating,” and “having” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Any use of any form of the terms “connect,” “couple,” “attach,” “mount,” or any other term describing an interaction between elements is intended to mean either an indirect or a direct interaction between the elements described. Moreover, any use of “top,” “bottom,” “above,” “below,” “upper,” “lower,” “up,” “down,” “vertical,” “horizontal,” “left,” “right,” and variations of these terms are made for convenience, but does not require any particular orientation of the components.

Certain terms are used throughout the description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function, unless specifically stated.

A hydrocarbon production system (e.g., an oil and gas production system) and/or an injection system may include electrical assets that may be controlled by a control system. The electrical assets controllable via the control system may couple together multiple surface (e.g., topside), subsea, and/or subsurface control units, applications, and/or components. For example, the control system may connect surface process and control components (e.g., a distributed control system, a subsea control module, and the like) with subsea tree modules (e.g., manifolds, pipeline sections, and the like) and subsurface (e.g., in-well) components to manage production and/or injection.

As such, the control system may access multiple sensors located at surface, subsea, and subsurface locations, to receive equipment status data, hydrocarbon production data, and/or injection flow data. The control system may include multiple control units, such as a distributed control system (DCS) and a master control system (MCS) communicatively coupled together, that receive information from the multiple sensors and control components of the production and/or an injection system at surface, subsea, and subsurface locations. For example, surface data (e.g., a water tank indicator, pressure at the surface, and the like) may be collected via sensors and sent to the distributed control system while subsea and subsurface data may be collected via sensors and sent to the master control system. A data exchange protocol may be used to integrate and exchange data between the distributed control system and the master control system. The distributed control system may include diagnostic and interpretation software interfaces that enable the distributed control system to control and/or program certain assets that control surface, subsea, and subsurface processes (e.g., via sequential instructions). Data received and/or interpreted from the sensors within certain operating parameters (e.g., above or below certain thresholds) may be flagged such that the distributed control system may issue (e.g., automatically or semi-automatically) commands to surface, subsea, and/or subsurface components of the hydrocarbon production system which perform tasks serving certain applications (e.g., initializing production, restarting production, increasing production, and the like) in response to the flagged parameters.

The production and/or injection system may include self-diagnostic and intelligent processes that may be performed by the control system. Multiple applications may be coordinated, synchronized, and connected to control dependent and independent activities via the control system. For example, well integrity and pipe integrity may be monitored using a single control unit (e.g., the distributed control system) as enabled by the data exchange protocol. The data exchange protocol may also enable performing specific functionalities, such as adjusting (e.g., optimizing) fracturing operations, performing periodic sampling, managing initial start-up procedures, managing start-up procedures from a shut-down of the production and/or injection system, and the like. The production and/or injection system may detect, predict, estimate, react, and/or manage well production and/or injection while factoring in equipment specifications used in the production and/or injection system (which may vary due to different vendors and/or suppliers).

With the foregoing in mind, FIG. 1 is a schematic diagram of a subsea hydrocarbon production system 10, in accordance with an embodiment of the present disclosure. As illustrated, the subsea hydrocarbon production system 10 is installed on a subsea field, which may include one or more subsea reservoirs 11. While the present disclosure and figures describe embodiments in terms of subsea hydrocarbon production systems, it should be understood that the present disclosure may apply to any suitable fluid production or injection system, such as other offshore production or injection applications, as well as onshore or surface production or injection applications. An injection system may include any suitable injection system, such as a chemical injection system, a water injection system, a steam injection system, and the like.

The production system 10 may include surface components 12 that are located at a surface level 14 (e.g., above a sea line or sea level 16). The production system 10 may include one or more computing devices 18. The computing device(s) 18 may include one or more control systems that control one or more components of the production system 10. The control system(s) may include a distributed control system 20 that may couple to one or more surface components 12. For example, the distributed control system 20 may couple to a water injection system 22, a methanol injection system 24, a diesel injection system 26, or any other suitable injection system. The distributed control system 20 may control (e.g., operation of) the water injection system 22, the methanol injection system 24, and/or the diesel injection system 26. The distributed control system 20 may also receive information (e.g., via one or more sensors) from the water injection system 22, the methanol injection system 24, and/or the diesel injection system 26. For example, the distributed control system 20 may receive an amount and/or an available capacity of water, methanol, and/or diesel in a tank of the water injection system 22, the methanol injection system 24, and/or the diesel injection system 26. The distributed control system 20 may include a processor 27 and a memory 28, as described in more detail below.

The control system(s) of the computing device(s) 18 may also include a master control system 29 that may couple to one or more surface components 12. For example, the master control system 29 may couple to an electrical power unit 30, a hydraulic power unit 32, and/or a topside umbilical termination assembly 34. The electrical power unit 30 may supply electrical power to other components of the production system 10, such as subsea and/or subsurface components. For example, the electrical power unit 30 may supply electrical power to one or more subsea trees 56 via one or more umbilicals (e.g., cables) 40. The hydraulic power unit 32 may supply hydraulic power to other components of the production system 10, such as subsea components. For example, the hydraulic power unit 32 may supply hydraulic power to the subsea tree(s) 56 via the umbilical(s) 40. In some embodiments of the production system 10, the production system 10 may be “all-electric” (e.g., not use hydraulic power), and thus not include the hydraulic power unit 32. The topside umbilical termination assembly 34 may be a termination point for the umbilical(s) 40. The topside umbilical termination assembly 34 may provide an interface between the umbilical(s) 40 and the master control system 29, and/or any other suitable surface control components. The master control system 29 may control the electrical power unit 30 to supply electrical power to components of the production system 10. The master control system 29 may also control the hydraulic power unit 32 to supply hydraulic power to components of the production system 10. The master control system 29 may further control the topside umbilical termination assembly 34 to supply and transfer consumables and/or communication signals between the surface components 12 and the subsea components 36, as well as any other suitable components (e.g., subsurface components 42), via the umbilical(s) 40. The master control system 29 may include a processor 27 and a memory 28, as described in more detail below.

The umbilical(s) 40 may supply and transfer consumables and/or communication signals between the surface components 12 and the subsea components 36, as well as any other suitable components (e.g., subsurface components 42). The subsea components 36 are located at a subsea level 44, between a mud line (e.g., subsea floor) 46 and the sea line 16. For example, the umbilical(s) 40 may supply air, gas, hydraulic power, electrical power, fiber optics, water, methanol, diesel, other chemicals, communication signals, and the like, to the subsea components 36. The umbilical(s) 40 may include liquid and/or chemical injection tubes, hydraulic supply tubes, electrical control signal cables, electrical power cables, fiber optic signal cables, air or gas tubes, and the like. A subsea umbilical termination assembly 48 may be another termination point for the umbilical(s) 40. The subsea umbilical termination assembly 48 may provide an interface between the umbilical(s) 40 and a subsea control system, such as one or more subsea control modules 38, and/or any other suitable subsea control components.

The subsea umbilical termination assembly 48 may couple to a subsea distribution unit 50 which may distribute or allocate the consumables to other subsea components and/or subsurface components of the production system 10. The subsea distribution unit 50 may be controlled by, for example, the subsea control module(s) 38, such that the consumables and/or communication signals supplied by the umbilical(s) 40 may be distributed or allocated to other subsea components and/or subsurface components based on instructions sent by the subsea control module(s) 38. The production system 10 may produce fluids including hydrocarbons from one or more wells 54 that are disposed in and/or access the reservoir(s) 11. The production system 10 may include the subsea tree(s) 56, which may be installed on a well 54. Each subsea tree 56 may include a subsea control module 38, which, in some embodiments, may control the subsea distribution unit 50. For example, the subsea control module 38 may control the subsea distribution unit 50 to distribute or allocate a certain amount of consumables to the respective subsea tree 56. The subsea tree 56 may couple to the subsea distribution unit 50 via one or more flying leads 52 that may provide electrical connections, hydraulic connections, chemical connections, and the like.

The subsea tree 56 may also include a number of components, such as sampling module(s), choke(s), valve(s), and the like, which may be controlled by the subsea control module 38. The subsea tree 56 may be mounted on a subsea wellhead, that in turn may be installed on the well 54 and provide structural foundation for the well 54. The subsea tree 56 may include tubing 58 (e.g., one or more production tubing hangers) and/or accommodate hydraulic and/or electrical lines used for managing the subsurface (e.g., downhole) components 42, such as mandrels, valves, sensors, flowmeters, and the like. The subsea tree 56 may control and manage pressure and production flow in the well 54. The tubing 58 may extend into a subsurface level 47 (e.g., below the mud line 46) and access the reservoir 11 to produce hydrocarbons from and/or inject water, chemicals, steam, and the like, to the reservoir 11. The well 54 may include one or more zones (e.g., 60, 62), where sensors and/or flow control devices may be installed to monitor and/or control production flow in the well 54. While only two zones 60, 62 of the well(s) 54 are illustrated, the present disclosure contemplates any suitable number of zones of the well(s) 54 (e.g., 1-100, or fewer, or more).

The subsea control module 38 may be attached to or included in the subsea tree 56 and include instrumentation, electrical connections, hydraulic connections, and the like, for operating the subsea components 36 via the flying lead(s) 52 and/or the subsurface components 42. The subsea control module 38 may include a processor 27 and a memory 28, as described in more detail below. One or more jumpers 64 (e.g., sections of pipeline) may transfer liquids (e.g., production) between subsea components 36. As illustrated, the jumper(s) 64 carries production downstream from the subsea tree 56. The jumper(s) 64 may route production through one or more multiphase flowmeters to measure production rates and/or volumes.

The jumper(s) 64 couple the subsea tree(s) 56 to a pipeline end manifold 66 and send production from the well(s) 54 to the pipeline end manifold 66. Produced fluid from multiple wells 54 may be commingled in the pipeline end manifold 66 via multiple jumpers 64 before being directed to a flowline 72. The pipeline end manifold 66 may also include a number of components, such as choke(s), valve(s), and the like, which may be controlled by the subsea control module 38. The pipeline end manifold 66 may also include a pig launcher 68 that launches a pig used to clean and/or monitor the inside of a pipeline. A corresponding pig receiver 70 may be located at the surface level 14. Operating the pig, the pig launcher 68, and/or the pig receiver 70 may also be controlled by the subsea control module 38.

The flowline 72 may be coupled to a riser base 74, which provide one or more connections to one or more risers 76. The riser(s) 76 may transfer the production from the subsea floor 46 to surface components 12 e.g., one or more production and/or processing facilities) at the surface level 14.

As mentioned above, the distributed control system 20, the master control system 29, and the subsea control module 38 may include one or more processors 27 (e.g., a microprocessor(s)) that may execute software programs or computer-executable instructions. Moreover, the processor(s) 27 may include multiple microprocessors, one or more “general-purpose” microprocessors, one or more special-purpose microprocessors, and/or one or more application specific integrated circuits (ASICs), or some combination thereof. For example, the processor(s) 27 may include one or more reduced instruction set computer (RISC) processors.

The distributed control system 20, the master control system 29, and the subsea control module 38 may include one or more memory devices 28 that may store information such as control software, look up tables, configuration data, etc. The memory device(s) 28 may include a tangible, non-transitory, machine-readable medium, such as a volatile memory (e.g., a random access memory (RAM)) and/or a nonvolatile memory (e.g., a read-only memory (ROM), a flash memory, a hard drive, or any other suitable optical, magnetic, or solid-state storage medium, or a combination thereof). The memory device(s) 28 may store a variety of information and may be used for various purposes. For example, the memory device(s) 28 may store machine-readable and/or processor-executable instructions (e.g., firmware or software) for the processor 14 to execute. In some embodiments, the distributed control system 20 and master control system 29 may be incorporated in a single control system, and share processor(s) 27 and/or memory device(s) 28.

FIG. 2 is a block diagram illustrating control relationships 90 between components of the production system 10 of FIG. 1, in accordance with an embodiment of the present disclosure. The distributed control system 20 may control surface components 12 that are located at the surface level 14. The surface components 12 are described in more detail below. The distributed control system 20 may communicate with and send and/or receive instructions to and from the master control system 29. The master control system 29 is communicatively coupled to and may control the hydraulic power unit 32, the electrical power unit 30, and the topside umbilical termination assembly 34. The master control system 29 may also send and/or receive instructions to and from the subsea umbilical termination assembly 48, the subsea distribution unit 50, and/or the subsea control module(s) 38, via the topside umbilical termination assembly 34 and the umbilical(s) 40. The subsea control module 38 may control the subsurface components 42, the subsea tree components 92, and the pipeline end manifold components 94. The subsea tree components 92 and the pipeline end manifold components 94 are described in more detail below. Although communication relationships described in FIG. 3 indicate a particular set of relationships, it should be noted that the relationships may be manipulated in a number of arrangements and should not be limited to the depicted embodiment.

FIG. 3 is a block diagram of components controlled by the distributed control system 20 of FIG. 1, in accordance with an embodiment of the present disclosure. The distributed control system 20 may control certain surface components 12. As illustrated, the distributed control system 20 controls one or more pumps 100 that may facilitate processing production. The pump(s) 100 may include one or more single-phase pumps, one or more multi-phase pumps, one or more hybrid pumps, or any other suitable pump. The distributed control system 20 may also control a separator 102. The separator 102 may separate non-production matter, such as water, sand, mud, sediment, or any other suitable matter, from production.

The distributed control system 20 may also control one or more motors 104. For example, the distributed control system 20 may control a motor 104 to supply mechanical power to a generator 106. The distributed control system 20 may control the generator 106 to convert the mechanical power from the motor 104 to electrical power and supply the electrical power to the other surface components 12, the subsea components 36 and/or the subsurface components 42. In some embodiments, the distributed control system 20 may control a hydraulic motor to supply hydraulic power to the other surface components 12, the subsea components 36 and/or the subsurface components 42. The distributed control system 20 may also control a gas compressor 108. The gas compressor 108 may increase production recovery and/or enable longer transport distances by pressurizing the production.

In addition, the distributed control system 20 may also control the water injection system 22, the methanol injection system 24, and/or the diesel injection system 26. The water injection system 22 may inject water into components of the production system 10 to facilitate maintaining pressure in the production system 10 and driving production. The methanol injection system 24 may inject methanol to, for example, pipelines of the production system 10 and/or the subsea tree 56 reduce formation of hydrate plugs. In some embodiments, the methanol injection system 24 may be any suitable gas injection system that, for example, injects gas into the pipelines of the production system 10 and/or the subsea tree 56 to reduce formation of hydrate plugs. The diesel injection system 26 may inject diesel into, for example, the well(s) 54 at the subsurface level 47, the riser 76 at the subsea level 44, and/or the flowline 72 at the subsea level 44, to facilitate drilling and/or maintaining the well(s) 54. In some embodiments, the diesel injection system 26 may be any chemical injections ystem that may inject any suitable chemicals into, for example, the well(s) 54 at the subsurface level 47, the riser 76 at the subsea level 44, and/or the flowline 72 at the subsea level 44, to facilitate drilling and/or maintaining the well(s) 54.

FIG. 4 is a block diagram of components controlled by the subsea control module 38 of FIG. 1, in accordance with an embodiment of the present disclosure. The subsea control module 38 may control certain subsurface components 42, subsea tree components 92, pipeline end manifold (PLEM) components 94, and/or a high integrity pressure protection system 120. The subsurface components 42 are located at the subsurface level 47. The subsurface components 42 that may be controlled by the subsea control module 38 may include one or more chemical injection mandrels 122. The chemical injection mandrel(s) 122 may extend into the well(s) 54 and inject one or more chemicals into the well(s) 54. For example, the chemical injection mandrel(s) 122 may inject one or more chemical dispersants into an uncontained oil plume resulting from a blowout. The subsurface components 42 may also include one or more gas injection valves 124. The subsea control module 38 may control the gas injection valve(s) 124 to inject gas into the well(s) 54 and increase pressure in the well(s) 54 to control production. The subsea control module 38 may also control one or more flow control valves 126 disposed at the subsurface level 47 (e.g., in the well(s) 54) to reduce water cut (i.e., water content in the production flow), reduce gas cut (i.e., gas content in the production flow), reduce solids (e.g., sand, fines, silt, and the like) in the production, reduce well intervention, and/or increase production. The subsea control module 38 may control one or more inflow control valves 128 to reduce or stop flow of matter (e.g., undesirable matter) into the well(s) 54. In some instances, the subsea control module 38 may control the inflow control valve(s) 128 to reduce unwanted matter (e.g., fluids) from entering the well(s) 54.

The subsea tree components 92 that may be controlled by the subsea control module 38 may include the subsea tree 56 itself. For example, the subsea control module 38 may control the subsea tree 56 to monitor and/or control production of the respective well 54. The subsea control module 38 may control the subsea tree 56 to manage fluids and/or gas injected into the respective well 54. The subsea control module 38 may also control a sampling module 130 of the subsea tree 56. That is, the subsea control module 38 may control the sampling module 130 to gather and/or analyze samples of fluid or other matter near the subsea tree 56. In some embodiments, the sampling may be performed by a remote operated vehicle (ROV), which may be controlled by the subsea control module 38. The subsea control module 38 may control one or more subsea tree chokes 132 to control flow of the production. The subsea control module 38 may control one or more subsea tree valves 134 to at least partially enable and/or disable production flow, fluid injection, gas injection, and the like.

The pipeline end manifold components 94 that may be controlled by the subsea control module 38 may include the pipeline end manifold 66 itself. The subsea control module 38 may control the pipeline end manifold 66 to control commingling of production flow from one or more input jumpers 64 transferring production from one or more well(s) 54. The subsea control module 38 may also control one or more pipeline end manifold chokes 136 to control flow of production from one or more input jumpers 64 transferring production from one or more well(s) 54. The subsea control module 38 may control one or more pipeline end manifold valves 138 to at least partially enable and/or disable production flow from a respective input jumper 64 transferring production from a respective well(s) 54. The subsea control module 38 may also control the pig launcher 68 and/or the pig receiver 70 to launch, receive, or otherwise operate the pig (e.g., to clean and/or monitor the inside of a pipeline).

The subsea control module 38 may also control a high integrity pressure protection system 120, which may prevent over-pressurization of the production system 10. For example, the subsea control module 38 may control the high integrity pressure protection system 120 to shut off a source of high pressure before a pressure threshold of the production system 10 is exceeded, preventing loss of containment via rupture of a portion of the production system 10.

FIG. 5 is a block diagram illustrating an example of communication routing in the production system 10 of FIG. 1, in accordance with an embodiment of the present disclosure. In one embodiment, the distributed control system 20 may be communicatively coupled to the subsea distribution unit 50, which may in turn be communicatively coupled to the subsea control module(s) 38. The production system 10 may include multiple wells 54, each of which may be coupled to a subsea tree 56 which may, in turn, include or be attached to a subsea control module 38. As such, the subsea distribution unit 50 may route and/or receive communications from the distributed control system 20 to and/or from one or more appropriate subsea control modules 38, based on identification of the one or more appropriate subsea control modules 38 by the distributed control system 20 and/or the contents of the communications. In this manner, the distributed control system 20 may send instructions to or request information from one or more targeted subsea control modules 38.

FIG. 6 is a block diagram illustrating informational relationships between components of the production system 10 of FIG. 1, in accordance with an embodiment of the present disclosure. The distributed control system 20 may communicatively couple to one or more surface sensors 140. The surface sensor(s) 140 may include a water tank indicator 142 that may determine an amount and/or an available capacity of water in a tank of the water injection system 22. The surface sensor(s) 140 may also include a methanol tank indicator 144 that may determine an amount and/or an available capacity of methanol in a tank of the methanol injection system 24. The surface sensor(s) 140 may further include a diesel tank indicator 146 that may determine an amount and/or an available capacity of diesel in a tank of the diesel injection system 26. The surface sensor(s) 140 may also include one or more pressure sensors 148 that may determine pressure of the production arriving at the surface level 14 (e.g., at a storage device/facility and/or a processing facility located at the surface). The surface sensor(s) 140 may include one or more temperature sensors 150 that may determine temperature in the production arriving at the surface level 14. The surface sensor(s) 140 may also include one or more flow rate sensors 152 that may determine flow rate of the production arriving at the surface level 14.

The distributed control system 20 may communicatively couple to the subsea distribution unit 50, which may in turn communicatively couple to the subsea control module(s) 38. Each subsea control module 38 may communicatively couple to one or more subsea sensors 158 that may be located at the subsea level 44. The subsea sensor(s) 158 may include one or more vibration sensors 160 that may detect vibration and/or determine a degree of the vibration at the subsea level 44. The subsea sensor(s) 158 may also include one or more pressure sensors 162 that may determine pressure at the subsea level 44. The subsea sensor(s) 158 may further include one or more temperature sensors 164 that may determine temperature at the subsea level 44. The subsea sensor(s) 158 may include one or more flow rate sensors 166 that may determine flow rate of production and/or other fluids (e.g., from injection) at the subsea level 44. The subsea sensor(s) 158 may also include a multiphase flowmeter 168 that may determine production rates and/or volumes based on the production flow measured by the multiphase flowmeter 168.

The subsea control module 38 may also communicatively couple to one or more subsurface sensors 170 that may be located at the subsurface level 47 (e.g., downhole in the well(s) 54). The subsurface sensor(s) 170 may include one or more downhole flow rate sensors 172 that may determine flow rate of production and/or other fluids (e.g., from injection) in the well(s) 54 and/or at the subsurface level 47. The subsurface sensor(s) 170 may also include one or more downhole pressure sensors 174 that may determine pressure in the well(s) 54 and/or at the subsurface level 47. The subsurface sensor(s) 170 may further include one or more downhole temperature sensors 176 that may determine temperature in the well(s) 54 and/or at the subsurface level 47. The subsurface sensor(s) 170 may also include one or more density sensors 178 that may determine density (e.g., of the production) in the well(s) 54 and/or at the subsurface level 47. The subsurface sensor(s) 170 may further include one or more sand detection sensors 180 that may determine a quantity of sand (e.g., in the production flow) in the well(s) 54 and/or at the subsurface level 47. The subsurface sensor(s) 170 may also include one or more micro seismic sensors 182 that may determine seismic reading and/or detect seismic events (e.g., earthquakes) in the well(s) 54 and/or at the subsurface level 47. The subsurface sensor(s) 170 may further include one or more downhole water cut sensors 184 that may determine water content (e.g., in the production flow) in the well(s) 54 and/or at the subsurface level 47.

Initializing Production

FIG. 7 is a flowchart of a method 200 for starting the production system 10 of FIG. 1, in accordance with one or more embodiments of the present disclosure. Starting the production system 10 may occur after setting up and installing the components of the production system 10 on the field, the well(s) 54, and the reservoir 11, for the first time. While the method 200 is described using steps in a specific sequence, it should be understood that the present disclosure contemplates that the described steps may be performed in different sequences than the sequence illustrated, and certain described steps may be skipped or not performed altogether. In some embodiments, the method 200 may be implemented by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as the memory(s) 28, using a processor, such as the processors 27.

Prior to starting the production system 10, the distributed control system 20 may receive an indication that preparation for starting the production system 10 is complete. For example, the preparation may include preparing the water injection system 22, pressurizing the methanol injection system 24, pressurizing the diesel injection system 26, and the like. As such, the indication that preparation for starting the production system 10 is complete may include one or more indications that the water injection system 22 is prepared, the methanol injection system 24 is pressurized at a methanol injection system pressure threshold, the diesel injection system 26 is pressurized at a diesel injection system pressure threshold, and the like.

The distributed control system 20 may determine (process block 202) a startup sequence for production at the well(s) 54. The startup sequence may differ from one well to another and may depend on a number of variables, such as previous work performed in the well during drilling and completion operations, a layout of the production system 10, surface process constrains, reservoir conditions, well design, anticipated flow assurance challenges, production priorities, and/or targets.

In some embodiments, the startup sequence may be authorized (e.g., by the distributed control system 20) based on health, safety, and/or environmental concerns. For example, the distributed control system 20 may automatically authorize activities of the startup sequence that are considered nonhazardous to the operation of the production system 10 and/or the environment. In some embodiments, the distributed control system 20 may automatically authorize nonhazardous activities when sensors of the production system 10 verify data associated with the nonhazardous activities and/or confirm that specific criteria (e.g., thresholds) associated with the nonhazardous activities have been met. Activities that are considered to be hazardous to the operation of the production system 10 and/or the environment may be authorized, for example, through human interaction with the distributed control system 20. For example, an operator may examine the data associated with the hazardous activities and verify the data obtained from the sensors of the production system 10. Once verified, the operator may manually authorize a hazardous activity via the distributed control system 20 and the distributed control system 20 may proceed to the next operational sequence.

The startup sequence may include sequentially starting multiple wells 54. The order of starting the wells 54 may be determined using any suitable metric, including starting wells that have superior hydrocarbon quality to achieve faster production system startup before starting wells that have inferior hydrocarbon that may use water injection (and thus take more time) to start. In this manner, the production system 10 may start producing hydrocarbons in less time.

The distributed control system 20 may then start (process block 204) the production system 10 based on the startup sequence. The distributed control system 20 may start the production system 10 by instructing components of the production system 10 (e.g., the master control system 29, the electrical power unit 30, the hydraulic power unit 32, the surface components 12, the subsea distribution unit 50, the subsea control module 38, the subsurface components 42, the subsea tree components 92, the pipeline end manifold components 94, and the like) to start production. For example, the distributed control system 20 may adjust or open valves (e.g., the flow control valve(s) 126, the subsea tree valve(s) 134, the pipeline end manifold valve(s) 138, and the like) and/or chokes (e.g., the subsea tree choke(s) 92, the pipeline end manifold choke(s) 136, and the like) of the production system 10, start pumps of the production system 10, and the like.

The distributed control system 20 may then determine (decision block 206) whether water cut and/or gas cut in the production fluids is above a water cut and/or gas cut threshold. The water cut and/or the gas cut of the production may be determined by one or more subsurface sensors 170, such as the downhole water cut sensor(s) 184, at the zone(s) 60, 62 of the well(s) 54 at the subsurface level 47. As such, the distributed control system 20 may determine the water cut and/or the gas cut for each zone 60, 62. The distributed control system 20 may determine whether the water cut and/or the gas cut in the production is above the water cut and/or gas cut threshold. The water cut threshold may correspond to an amount or percentage (e.g., between 70 and 100 percent) of water content in the production such that producing an amount of hydrocarbons from the production is not economical. For example, if the water cut in the production is above the water cut threshold, then the cost of rendering usable hydrocarbons from the production may be greater than revenue realized from the resulting hydrocarbon production. Similarly, the gas cut threshold may correspond to an amount or percentage (e.g., between 70 and 100 percent) of gas content in the production such that producing an amount of hydrocarbons from the production is not economical.

If the distributed control system 20 determines (decision block 206) that the water cut and/or gas cut in the production is above the water cut and/or gas cut threshold, the distributed control system 20 may adjust (process block 208) flow of the production at zone(s) 60, 62 of the well(s) 54. In some embodiments, the distributed control system 20 may instruct flow control devices (e.g., the flow control valve(s) 126) located at target zone(s) 60, 62 to adjust the production flow to reduce the water cut and/or gas cut at that target zone. The distributed control system 20 may also instruct the flow control device(s) at a first zone(s) (e.g., 60) to adjust the production flow while not adjusting other flow control device(s) at a second zone(s) (e.g., 62), based on the water cut and/or gas cut being too high at the first zone(s) but not at the second zone(s). The distributed control system 20 may then return to decision block 206.

If the distributed control system 20 determines (decision block 206) that the water cut and/or the gas cut in the production is below the water cut and/or gas cut threshold, the distributed control system 20 may determine (decision block 210) whether a quality of commingling the production (e.g., with other production(s) from other well(s) 54) is above a commingling threshold. For example, at the pipeline end manifold 66, multiple productions provided by multiple jumpers 64 from multiple wells 54 may be commingled (e.g., combined, mixed, or blended together). One or more multiphase flowmeters 168 (e.g., located at the pipeline end manifold 66) may provide, measure, and/or test commingling information from the commingled productions and determine whether one or more commingling metrics are met or exceeded. The commingling information and metrics may include a flow rate of the commingled productions, a temperature of the commingled productions, a pressure of the commingled productions, a water cut of the commingled productions, a gas cut of the commingled productions, a fluid separation in the commingled productions, an amount or percentage of solids (e.g., fine solids) in the commingled productions, and the like. The distributed control system 20 may determine whether the quality of commingling the production is above a commingling threshold by comparing the commingling metric(s) of the production to one or more commingling thresholds (e.g., comparing a flow rate of the commingled productions to a commingling flow rate threshold).

If the distributed control system 20 determines (decision block 210) that the quality of commingling the production is below some commingling threshold, the distributed control system 20 may adjust (process block 212) the flow of the production at the subsea tree 56 and/or the pipeline end manifold 66. In some embodiments, the distributed control system 20 may instruct chokes (e.g., the subsea tree choke(s) 92 and/or the pipeline end manifold choke(s) 136) to adjust the production flow to change the quality of commingling in the commingled production. For example, the distributed control system 20 may instruct the chokes to restrict production flow from a well 54 with undesirable characteristics (e.g., insufficient pressure, temperature, and the like), such that the quality of commingling in the commingled production increases. The distributed control system 20 may then return to decision block 210 to determine whether the quality of commingling the production is now above the commingling threshold.

If the distributed control system 20 determines (decision block 210) that the quality of commingling the production is above the commingling threshold, the distributed control system 20 may determine (decision block 214) whether an arrival pressure and/or an arrival flow rate of the production is above an arrival pressure threshold and/or an arrival flow rate threshold. The arrival pressure and/or the arrival flow rate of the production may correspond to the pressure and/or flow rate of the production when the production arrives at the surface level 14 (e.g., at a storage device/facility and/or a processing facility located at the surface). The arrival pressure and/or the arrival flow rate of the production may be determined by the pressure sensor(s) 148 and/or the flow rate sensor(s) 152.

If the distributed control system 20 determines (decision block 214) that the arrival pressure and/or the arrival flow rate of the production is below the arrival pressure and/or arrival flow rate threshold, the distributed control system 20 may adjust (process block 212) the flow of the production at the subsea tree 56 and/or the pipeline end manifold 66, as described above. If the distributed control system 20 determines (decision block 214) that the arrival pressure and/or the arrival flow rate of the production is above an arrival pressure and/or arrival flow rate threshold, the distributed control system 20 may determine (decision block 216) whether bottom hole pressure in the well(s) 54 is above a bottom hole pressure threshold. The bottom hole pressure may be determined using the downhole pressure sensor(s) 174.

In some embodiments, the bottom hole pressure may be determined by performing a well test (e.g., a pressure buildup test). The distributed control system 20 may perform one or more well tests by testing various choke settings using the separator 102. While performing the well test(s), the distributed control system 20 may stop production from the well(s) 54. For example, a well test may include increasing pressure in at least a portion of the production system 10 and opening or closing one or more chokes (e.g., the subsea tree choke(s) 132 and/or the pipeline end manifold choke(s) 136). The distributed control system 20 may collect and analyze data resulting from the well test(s), including the bottom hole pressure. In some embodiments, the distributed control system 20 may determine whether to extend a well test currently in progress, modify subsequent well test(s) based on a previous or current well test(s), and the like, to accurately determine the bottom hole pressure. For example, during an exploration phase, the bottom hole pressure may be determined using pressure gauges installed on a drill stem testing string disposed in a well 54.

If the well 54 is completed, the bottom hole pressure may be determine from permanent downhole gauges installed in a lower completion. The bottom hole pressure threshold may be a bottom hole pressure that enables a rate of production from the wells (54) that is economical. For example, if the bottom hole pressure is below the bottom hole pressure threshold, then increasing the bottom hole pressure to produce hydrocarbons in the wells (54) may cost more than revenue realized from the resulting hydrocarbon production.

The distributed control system 20 may then increase pressure in the production system 10 and reheat at least some production transfer components (e.g., the jumper(s) 64, the flowline(s) 72, and the like) of the production system 10. The distributed control system 20 may instruct components of the production system 10 to restart the well(s) 54 when the well(s) 54 is stabilized (e.g., producing hydrocarbons at an approximately constant rate). The distributed control system 20 may then stop production from the well(s) 54 using new choke settings. The distributed control system 20 may reheat at least some production transfer components of the production system 10 while the well(s) 54 is not producing hydrocarbons. The distributed control system 20 may determine whether the bottom hole pressure in the well(s) 54 is equal to the bottom hole pressure threshold.

If the distributed control system 20 determines (decision block 216) that the bottom hole pressure is below the bottom hole pressure threshold, the distributed control system 20 may increase (process block 218) the bottom hole pressure. For example, the distributed control system 20 may instruct the water injection system 22 to inject water into portions of the well(s) 54 to increase bottom hole pressure. In some circumstances, if the bottom hole pressure is below the bottom hole pressure threshold, the distributed control system 20 may adjust the production rates for the well(s) 54 to adjust (e.g., optimize) the flowing conditions or shut in the well(s) 54. For example, the distributed control system 20 may adjust or close valves (e.g., the flow control valves 126) and/or chokes (e.g., the subsea tree choke(s) 92 and/or the pipeline end manifold choke(s) 136) of the production system 10, stop pumps of the production system 10, and the like. In some embodiments, if the bottom hole pressure is between a first (e.g., greater) bottom hole pressure threshold and a second (e.g., lower) bottom hole pressure threshold, the distributed control system 20 may instruct the water injection system 22 to inject water into the well(s) 54. If the bottom hole pressure is below the second bottom hole pressure threshold, then the distributed control system 20 may shut in the well(s) 54.

If the distributed control system 20 determines (decision block 216) that the bottom hole pressure is above the bottom hole pressure threshold, the distributed control system 20 may determine (decision block 220) whether an associated rate of production is above a production rate threshold. The rate of production may be determined using the multiphase flowmeter 168. In some embodiments, the distributed control system 20 may use software (e.g., stored in the memory(s) 28 and run by the processor(s) 27), such as reservoir management software applications, to determine whether the rate of production from the reservoir 11 and/or the well(s) 54 is greater than the production rate threshold.

If the distributed control system 20 determines (decision block 220) that the rate of production is below the production rate threshold, the distributed control system 20 may adjust (process block 222) operation of certain components to adjust the flow of production in the production system 10. The distributed control system 20 may adjust any suitable chokes and/or flow control devices (e.g., flow control valve(s) 126, subsea tree choke(s) 132, subsea tree valve(s) 134, pipeline end manifold choke(s) 136, pipeline end manifold valve(s) 138, and the like) to adjust (e.g., increase) the flow of production. In some embodiments, the production flow may be adjusted such that certain parameters, such as bubble pint temperature, flow pressure, sand production rate, and the like, are met, increased, or decreased, to prevent high pressure drawdowns which may lead to early breakthrough of sand and water production.

If the distributed control system 20 determines (decision block 220) that the rate of production is above the production rate threshold, the distributed control system 20 may continue (process block 224) the production with current settings. In this manner, increased hydrocarbon production using the production system 10 and increased life of the production system 10 may be realized by reducing negative impacts on pressure in the well(s) 54 (e.g., decreasing pressure in the well(s) 54), negative impacts on the reservoir 11 (e.g., decreasing pressure in the reservoir 11), and avoiding plugs in the production system 10.

Restarting Production

FIG. 8 is a flowchart of a method 300 for restarting the production system 10 of FIG. 1 (e.g., after an unplanned shutdown of the production system 10), in accordance with one or more embodiments of the present disclosure. The production system 10 may be shutdown for a variety of reasons, planned and unplanned. For example, the production system 10 may be shutdown to prevent a blowout, for safety reasons, temperature or pressure values exceeding temperature or pressure thresholds, inclement weather, and the like. While the method 300 is described using steps in a specific sequence, it should be understood that the present disclosure contemplates that the described steps may be performed in different sequences than the sequence illustrated, and certain described steps may be skipped or not performed altogether. In some embodiments, the method 300 may be implemented by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as the memory(s) 28, using a processor, such as the processors 27.

The distributed control system 20 may receive (process block 302) an indication that the production system 10 has shutdown. The indication may be based on information provided by one or more sensors of the production system 10, such as any of the surface sensors 140, the subsea sensors 158, or the subsurface sensors 170 of FIG. 6. For example, the surface flow rate sensor(s) 152, the subsea flow rate sensor(s) 166, the multiphase flowmeter 168, and/or the downhole flow rate sensor(s) 172 may provide the indication based on decreasing flow rate of the production or a flow rate below a flow rate threshold.

The distributed control system 20 may then determine (process block 304) a restart setup time of the production system 10. The restart setup time may be a duration of time before attempting to restart the production system 10 (e.g., as measured from shutting down the production system). The restart setup time may be estimated by determining durations of times for at least some, if not all, processes associated with starting the production system 10. The restart setup time may include a total time to ensure the processes and components of the production system 10 are integrated together and working as a system. The restart setup time may include durations of times for contingencies associated with resolving problems that might arise during a startup sequence.

The restart setup time may be based at least in part on production flow information. The production flow information may be provided by, for example, the surface flow rate sensor(s) 152, the subsea flow rate sensor(s) 166, the multiphase flowmeter 168, the downhole flow rate sensor(s) 172, and the like. Moreover, restarting the production system 10 and/or the restart setup time may account for more than solely electrical and mechanical considerations. For example, the restart setup time may be based at least in part on fluid dynamics effects, erosion of reservoir rocks (e.g., sediment) to avoid production of fines and sand, avoiding skin buildup at a sand face, and the like. In some embodiments, the restart setup time may include time associated with reducing health, safety, and environmental risks. In this manner, the restart setup time may realize an efficient time to startup the production system 10 while reducing risk and resource wastefulness.

After determining the restart setup time, the distributed control system 20 may depressurize (process block 306) the riser 76 and/or the flowline 72. For example, the distributed control system 20 may instruct the diesel injection system 26 to depressurize the riser 76 and/or the flowline 72 by injecting diesel into the riser 76 and/or the flowline 72.

The distributed control system 20 may preserve (process block 308) the subsea tree 56 (e.g., flush the subsea tree 56 to maintain production flow and prevent flow reduction in the subsea tree 56). The distributed control system 20 may preserve components of the production system 10 through chemical methods, thermal methods, hydraulic methods, or process methods. In some embodiments, the distributed control system 20 may preserve components of the production system 10 using chemical methods by flushing the components (e.g., the subsea tree 56, one or more pipelines, the well(s) 54, and the like) with chemicals to reduce a possibility of a flow assurance risk occurrence or prevent flow reduction or blockage. Additionally or in the alternative, the distributed control system 20 may preserve components of the production system 10 using thermal methods by using direct electrical heating or heat tracers to heat components or areas of the production system 10. The amount of heat applied may be calculated based on environmental conditions, production fluid conditions, and cooldown times.

For example, the distributed control system 20 may hydraulically displace production fluids and inject chemical inhibitors to change composition of the production fluid to move the production fluid outside a hydrate region. The distributed control system 20 may instruct the methanol injection system 24 to preserve the subsea tree 56 and/or the jumper 64 by injecting methanol into the subsea tree 56 and/or the jumper 64.

The distributed control system 20 may also preserve (process block 310) a pipeline (e.g., displace live production fluid in the pipeline to maintain production flow and prevent flow reduction in the pipeline) of the production system 10. For example, the distributed control system 20 may hydraulically replacing live production fluid in the pipeline with a relatively thick oil or residue that has lost its volatile components (e.g., hot dead oil) which sets cool downtime specifications. For example, the distributed control system 20 may instruct the pig launcher 68 and/or pig receiver 70 to launch a pig that interfaces production in the pipeline with a relatively thick oil or residue that has lost its volatile components (e.g., dead oil) to displace production in the pipeline (e.g., by ensuring complete displacement of water at low points). The pipeline may include, for example, the jumper(s) 64, the flowline 72, the riser 76, or any other suitable pipeline that at least partially transfer production from the well(s) 54 to the surface level 14.

The distributed control system 20 may then preserve (process block 312) the well(s) 54 (e.g., flush the well(s) 54 to maintain production flow and prevent flow reduction in the well(s) 54). The distributed control system 20 may preserve the well(s) 54 and tubing(s) 58 by injecting chemicals into the well(s) 54. For example, the distributed control system 20 may instruct the methanol injection system 24 to inject methanol into the well(s) 54 and/or the tubing(s) 58 located in the well(s) 54.

The distributed control system 20 may determine (decision block 314) whether the restart setup time has elapsed. The restart setup time may be a duration of time before restarting the production system 10 may be attempted (e.g., from when the production system 10 was shut down), and may be based at least in part on ensuring processes and components of the production system 10 are integrated together, contingencies associated with resolving problems that might arise during a startup sequence, production flow information, and/or reducing health, safety, and environmental risks.

If the distributed control system 20 determines (decision block 314) the restart setup time has not elapsed, the distributed control system 20 may wait (process block 316) until the restart setup time has elapsed.

The distributed control system 20 may then restart (process block 316) production by injecting chemicals into the well(s) 54. For example, the distributed control system 20 may inject chemicals into the well(s) 54 using the chemical injection mandrel(s) 122 or other chemical injection devices (e.g., chemical injection valves). The distributed control system 20 may inject the chemicals into multiple wells 54 to restart the wells 54 simultaneously, sequentially, or any combination thereof.

The distributed control system 20 may determine an injection rate at which the chemicals are injected into the well(s) 54 (e.g., via the chemical injection mandrel(s) 122) based at least in part on a water cut and/or a pressure at each corresponding subsea tree 56. That is, for each well 54, the distributed control system 20 may determine a chemical injection rate. The water cut of the production may be determined by one or more subsurface sensors 170, such as the downhole water cut sensor(s) 184. The pressure at the subsea tree 56 may be determined by one or more subsea sensors 158, such as the pressure sensor(s) 162. For example, if the distributed control system 20 determines a higher water cut in a well 54, then the distributed control system 20 inject the chemicals into the well at a lower chemical injection rate.

The chemical injection rate may be determined to ensure quick restart, efficient commingling and ramp up according to available chemical injection capacity. In some embodiments, the operation and/or control of chemical injection (e.g., via the chemical injection mandrel(s) 122) may be synchronized with the operation and/or control of the subsea tree choke(s) 132 and/or subsea tree valve(s) 134.

Increasing Production

FIG. 9 is a flowchart of a method 400 for monitoring and increasing performance of the production system 10 of FIG. 1, in accordance with one or more embodiments of the present disclosure. The method 400 may enable the distributed control system 20 to monitor multiple components of the production system 10, including the surface components 12, the subsea components 92, 94, and the subsurface components 42, and increase efficiency and/or recovery of the production system 10 through synthesizing and analyzing information from the surface level 14, the subsea level 44, and the subsurface level 47. While the method 400 is described using steps in a specific sequence, it should be understood that the present disclosure contemplates that the described steps may be performed in different sequences than the sequence illustrated, and certain described steps may be skipped or not performed altogether. In some embodiments, the method 400 may be implemented by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as the memory(s) 28, using a processor, such as the processors 27.

The distributed control system 20 may receive (process block 402), at the surface level 14, subsea and/or subsurface information from the subsea control module 38. For example, the subsea and/or subsurface information may be provided by the subsea sensors 158 and/or the subsurface sensors 170 to the subsea control module 38. In some embodiments, the subsea and/or subsurface information may include water cut of the production, an amount or percentage of solids in the production, a flow rate of the production, a pressure of the production, a temperature of the production, and the like. The solids may include, without limitation, sand, fines (e.g., silt), and the like. In some embodiments, subsurface information may be collected by the subsurface sensors 170 at each zone 60, 62 of the well(s) 54.

The subsea control module 38 may then send the subsea and/or subsurface information to the distributed control system 20. In some embodiments, a data interface between the distributed control system 20 and the subsea control module 38 may be activated such that the distributed control system 20 and the subsea control module 38 may communicate and exchange information. For example, the distributed control system 20 may enter a reservoir management mode, which may activate the data interface, such that the distributed control system 20 may receive the subsea and/or subsurface information from the subsea or subsurface information. The reservoir management mode may invoke any relevant subsurface disciplines, such as geophysics, geology, petrophysics, geomechanics, geostatistics, and the like. The reservoir management mode may also invoke any relevant engineering disciplines, such as mechanical, simulation, completions, production, stimulation, artificial lift, and the like.

The distributed control system 20 may then determine (decision block 404) whether a water cut and/or a sand production in the production is above a water cut and/or sand production threshold. The water cut of the production may be determined by one or more subsurface sensors 170, such as the downhole water cut sensor(s) 184. The sand production may be determined by one or more subsurface sensors 170, such as the sand detection sensor(s) 180. The water cut restart threshold may correspond to an amount or percentage (e.g., between 70 and 100 percent) of water content in the production such that the production with the water cut threshold is economical. Similarly, the sand production threshold may correspond to a sand production such that the hydrocarbon production with the sand production threshold is economical. In some embodiments, the distributed control system 20 may additionally or alternatively determine whether an amount of solids in the production is above a solid production threshold, wherein the solid production threshold may correspond to a threshold amount of solids such that the hydrocarbon production with the solid production threshold is economical. In some embodiments, the distributed control system 20 may additionally or alternatively determine whether a gas cut of the production is above a gas cut threshold.

If the distributed control system 20 determines (decision block 404) that the water cut and/or the sand production in the production is above the water cut and/or sand production threshold, the distributed control system 20 may adjust (process block 406) positions of one or more flow control devices (e.g., the flow control valve(s) 126), one or more inflow control devices (e.g., the inflow control valve(s) 128), one or more chokes (e.g., the subsea tree choke(s) 132, the pipeline end manifold choke(s) 136), and the like, to reduce the water cut or the sand production in the production. In some embodiments, the distributed control system 20 may instruct the flow control device(s), the inflow control device(s), the choke(s), and the like, located at target zone(s) 60, 62 to adjust the production flow and/or inflow to reduce the water cut and/or the sand production. In some embodiments, the distributed control system 20 may ensure that the well(s) 54 are stable and outside a problematic window for production assurance issues such as wax buildup, asphaltene buildup, skin buildup at a sandface, and slug buildup.

The distributed control system 20 may also instruct the flow control device(s), the inflow control device(s), the choke(s), and the like, at a first zone(s) (e.g., 60) to adjust the production flow and/or inflow while not adjusting other flow control device(s), the inflow control device(s), the choke(s), and the like, at a second zones (e.g., 62), based on the water cut and/or sand production being too high at the first zone(s) but not at the second zone(s). The distributed control system 20 may then return to decision block 404.

If the distributed control system 20 determines (decision block 404) that the water cut and/or the sand production in the production is below the water cut and/or the sand production, the distributed control system 20 may determine (process block 408) a flow rate, pressure, and/or temperature of at least a portion of the production system 10 corresponding to increased production. For example, the distributed control system 20 may determine the flow rate, pressure, and/or temperature of at least the portion of the production system 10 corresponding to more efficient production, optimized production, and the like. The flow rate, pressure, and/or temperature corresponding to increased production may be determined by simulation, modeling, and the like. For example, the distributed control system 20 may use modeling software (e.g., stored in the memory(s) 28 and run by the processor(s) 27) to determine the flow rate, pressure, and/or temperature of at least the portion of the production system 10 corresponding to increased production. In some embodiments, the distributed control system 20 may determine the flow rate, pressure, and/or temperature of at least the portion of the production system 10 corresponding to increased production at each zone 60, 62.

The distributed control system 20 may then determine (decision block 410) whether a measured flow rate, pressure, and/or temperature of at least a portion of the production system 10 approximately match (e.g., within 0.1 to 10%) the flow rate, pressure, and/or temperature of at least the portion of the production system 10 corresponding to the increased production. The measured flow rate, pressure, and/or temperature may be determined based on the received subsea and/or subsurface information from process block 402. The flow rate, pressure, and/or temperature of at least the portion of the production system 10 corresponding to the increased production may be determined from process block 408. In some embodiments, matching the measured flow rate, pressure, and/or temperature with the flow rate, pressure, and/or temperature corresponding to the increased production may be performed for each zone 60, 62 of the well(s) 54.

If the distributed control system 20 determines (decision block 410) that the measured flow rate, pressure, and/or temperature does not approximately match the flow rate, pressure, and/or temperature corresponding to the increased production, the distributed control system 20 may adjust (process block 412) the flow control device(s) and/or the choke(s) based on the discrepancy.

For example, the distributed control system 20 may instruct the flow control device(s) and/or the choke(s) to adjust their respective settings, such that the resulting production approximately matches the flow rate, pressure, and/or temperature corresponding to the increased production. In some embodiments, the distributed control system 20 may instruct the flow control device(s) and/or the choke(s) at each zone 60, 62 to adjust their respective settings such that the resulting production approximately matches the flow rate, pressure, and/or temperature corresponding to the increased production at the respective zone 60, 62. The distributed control system 20 may then return to decision block 410.

If the distributed control system 20 determines (decision block 410) that the measured flow rate, pressure, and/or temperature approximately matches the flow rate, pressure, and/or temperature corresponding to the increased production, the distributed control system 20 may continue (process block 414) production with current settings. In this manner, increased hydrocarbon production using the production and/or injection system and increased life of the production and/or injection system may be realized while reducing negative impacts on pressure in the wells, negative impacts on the hydrocarbon reservoir, and preventing plugs from building up in the production and/or injection system.

Reference throughout this specification to “any embodiment,” “an embodiment,” “embodiments,” “some embodiments,” “certain embodiments,” or similar language means that a particular feature, structure, or characteristic described in connection with the embodiment may be included in at least one embodiment of the present disclosure. Thus, these phrases or similar language throughout this specification may, but do not necessarily, all refer to the same embodiment. Although the present disclosure has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the present disclosure, except to the extent that they are included in the accompanying claims. The present embodiments may not represent a complete description of each and every executed operation while producing from a subsea field.

While the embodiments set forth in the present disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. The disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.

The techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. These techniques provide specific implementations of a solution to a problem, with respect to modeling startup of a fluid production and/or injection system in the software arts, for non-limiting example, by dynamically modeling effects of operational procedures during the startup of the production system at different times throughout the life of the field and updating the operational procedures to account for changes in the field that may not have been accounted for earlier. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function] . . . ” or “step for [perform]ing [a function] . . . ,” it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f). 

What is claimed is:
 1. A system for starting production of fluids comprising hydrocarbons from a well disposed in a reservoir located at a subsurface level, comprising: a subsea tree coupled to the well and configured to control a flow of the production of the fluids comprising the hydrocarbons, wherein the subsea tree comprises: one or more subsea tree chokes configured to control the flow of the production at the subsea tree; one or more subsea tree valves configured to at least partially enable the flow of the production, inject additional fluids, inject gas, or any combination thereof, at the subsea tree; and a subsea control module configured to communicatively couple to one or more flow control valves located in the well, the one or more subsea tree chokes, the one or more subsea tree valves, or any combination thereof, wherein the one or more flow control valves are configured to reduce water cut in the production, reduce gas cut in the production, control the flow of the production at the well, reduce solids in the production, or any combination thereof; a distributed control system communicatively coupled to the subsea control module and located at a surface level, wherein the distributed control system comprises one or more processors configured to: send a first instruction to the one or more flow control valves to adjust the flow of the production of the well when the water cut or the gas cut in the production is above a water cut threshold or a gas cut threshold; send a second instruction to the one or more subsea tree chokes to adjust the flow of the production when a quality of commingling of the flow of the production with one or more additional flows of production from one or more additional wells is less than a commingling threshold, an arrival pressure is less than an arrival pressure threshold, or an arrival flow rate is less than an arrival flow rate threshold; and continue the production of the fluids comprising the hydrocarbons with current settings when a rate of the production is above a production rate threshold.
 2. The system of claim 1, wherein the subsea control module is communicatively coupled to one or more downhole water cut sensors located in the well, wherein the water cut or the gas cut is based at least in part on water cut information or gas cut information provided by the one or more downhole water cut sensors.
 3. The system of claim 1, wherein the subsea control module is communicatively coupled to one or more multiphase flowmeters located at a pipeline end manifold comprising one or more pipeline end manifold chokes configured to control the flow of the production at the pipeline end manifold and one or more pipeline end manifold valves configured to control the commingling of the flow of the production with one or more additional flows of production from one or more additional wells, wherein the quality of commingling the production is based at least in part on commingling information provided by the one or more multiphase flowmeters.
 4. The system of claim 1, wherein the distributed control system is communicatively coupled to one or more pressure sensors or one or more temperature sensors located at the surface level, wherein the arrival pressure or the arrival flow rate is based at least in part on arrival pressure information or arrival flow rate information provided by the one or more pressure sensors or the one or more temperature sensors.
 5. The system of claim 1, wherein the one or more processors are configured to send a third instruction to a water injection system of the system to increase bottom hole pressure of the well when the bottom hole pressure of the well is less than a bottom hole pressure threshold.
 6. The system of claim 5, wherein the subsea control module is communicatively coupled to one or more downhole pressure sensors located in the well, wherein the bottom hole pressure is based at least in part on bottom hole pressure information provided by the one or more downhole pressure sensors.
 7. The system of claim 1, wherein the one or more processors are configured to send a third instruction to the one or more flow control valves, the one or more subsea tree chokes, the one or more subsea tree valves, or any combination thereof to adjust the flow of the production when the rate of the production is less than the production rate threshold.
 8. The system of claim 1, wherein the well comprises a plurality of zones, wherein the first instruction is sent to a first set of the one or more flow control valves located in a first zone of the plurality of zones to adjust the flow of the production in the first zone when the water cut or the gas cut in the production at the first zone is above the water cut threshold or the gas cut threshold.
 9. The system of claim 8, wherein the first instruction is configured to prevent a second set of flow control valves located in a second zone of the plurality of zones to adjust the flow of production when the water cut or the gas cut in the production at the second zone is below the water cut threshold or the gas cut threshold.
 10. The system of claim 9, wherein the well comprises a plurality of downhole water cut sensors, wherein at least a first downhole water cut sensor of the plurality of downhole water cut sensors is located at the first zone, wherein at least a second downhole water cut sensor of the plurality of downhole water cut sensors is located at the second zone.
 11. The system of claim 10, wherein the water cut or the gas cut in the production in the first zone is based at least in part on water cut information or gas cut information provided by at least the first downhole water cut sensor, wherein the water cut or the gas cut in the production in the second zone is based at least in part on water cut information or gas cut information provided by at least the second downhole water cut sensor.
 12. A system for restarting production of fluids comprising hydrocarbons from a well after stopping the production, comprising: the well configured to produce the fluids comprising hydrocarbons from a hydrocarbon reservoir; a subsea tree mounted to the well and configured to transfer the production of the hydrocarbons from the well, wherein the subsea tree comprises a subsea control module configured to control one or more subsea components of the system; a plurality of pipelines configured to transfer the production of the fluids at least partially from the subsea tree to a surface level, wherein the plurality of pipelines comprises a flowline configured to transfer the production of the fluids from the subsea tree to a riser coupled to the flowline, wherein the riser is configured to transfer the production of the fluids from the flowline to the surface level; a gas injection system coupled to the subsea tree and the well and configured to inject gas into the subsea tree and the well; a pig launcher configured to displace the production with dead oil; a distributed control system communicatively coupled to the subsea control module and located at the surface level, wherein distributed control system comprises one or more processors configured to: send a first instruction to the gas injection system to inject the gas into the subsea tree to preserve the subsea tree; send a second instruction to the pig launcher to displace the production in at least one pipeline of the plurality of pipelines with the dead oil to preserve the at least one pipeline; send a third instruction to the gas injection system to inject the gas into the well to preserve the well; and restart the production at the well.
 13. The system of claim 12, wherein the one or more processors is configured to receive an indication that the system has shutdown prior to sending the first instruction.
 14. The system of claim 13, wherein the indication is based at least in part on sensor information provided by one or more sensors located at the surface level, a subsea level, a subsurface level, or any combination thereof.
 15. The system of claim 12, wherein the one or more processors are configured to send a fourth instruction to a chemical injection system coupled to the flowline and the riser, wherein the fourth instruction is configured to inject chemicals into the flowline and the riser to depressurize the riser and the flowline.
 16. The system of claim 12, wherein the one or more processors are configured to restart the production at the well by injecting chemicals into the well.
 17. The system of claim 16, wherein the one or more processors are configured to determine a chemical injection rate to inject the chemicals into the well based at least in part on a water cut at the subsea tree, a pressure at the subsea tree, or both.
 18. The system of claim 12, wherein the plurality of pipelines comprises a jumper coupled to the subsea tree, wherein sending the second instruction to the gas injection system to inject the gas into the subsea tree comprises injecting the gas into the jumper.
 19. A system for monitoring and increasing performance of production of fluids comprising hydrocarbons from a well, comprising: the well configured to produce the fluids comprising the hydrocarbons from a hydrocarbon reservoir, wherein one or more flow control devices and one or more inflow control devices are located in the well, wherein the one or more flow control devices are configured to reduce water cut in the production, reduce gas cut in the production, control a flow of the production at the well, or any combination thereof, wherein the one or more inflow control devices are configured to reduce flow of one or more undesired liquids into the well, from the well, or a combination thereof; a subsea tree mounted to the well and configured to transfer the production of fluids comprising the hydrocarbons from the well to a pipeline end manifold, wherein the subsea tree comprises a subsea control module and at least a first choke of a plurality of chokes, wherein the subsea control module is configured to control one or more subsea components of the system, wherein at least the first choke is configured to control the flow of the production at the subsea tree; the pipeline end manifold coupled to the subsea tree and comprising at least a second choke of the plurality of chokes, wherein at least the second choke is configured to control a flow of the production at the pipeline end manifold; a distributed control system communicatively coupled to the subsea control module and located at a surface level, wherein the distributed control system comprises one or more processors configured to: send a first instruction to adjust the one or more flow control devices, the one or more inflow control devices, at least the first choke, at least the second choke, or any combination thereof, when the water cut or a solid production in the production is above a water cut threshold or a solid production threshold; determine whether a measured flow rate, a measured pressure, a measured temperature, or any combination thereof, approximately matches a flow rate, pressure, a temperature, or any combination thereof, of the production corresponding to increasing the production; send a second instruction to adjust the one or more flow control devices, the one or more inflow control devices, or any combination thereof, when the measured flow rate, the measured pressure, the measured temperature, or any combination, does not approximately match the flow rate, the pressure, the temperature, or any combination thereof, corresponding to increasing the production; and continue the production with current settings when the measured flow rate, the measured pressure, the measured temperature, or any combination, approximately matches the flow rate, the pressure, the temperature, or any combination thereof, corresponding to increasing the production.
 20. The system of claim 19, wherein the one or more processors are configured to receive subsea or subsurface information from the subsea control module comprising the measured flow rate, the measured pressure, the measured temperature, or any combination, of the production.
 21. The system of claim 19, wherein the well comprises a plurality of zones, wherein each zone of the plurality of zones comprises a respective measured flow rate, the measured pressure, the measured temperature, or any combination, of the production.
 22. The system of claim 21, wherein the one or more processors are configured to determine whether the water cut or the solid production in the production is above the water cut threshold or the solid production threshold at each zone of the plurality of zones.
 23. The system of claim 22, wherein the first instruction is sent only to the one or more flow control devices, the one or more inflow control devices, at least the first choke, at least the second choke, or any combination thereof, in each zone of the plurality of zones where the water cut or the solid production at the zone is above the water cut threshold or the solid production threshold.
 24. The system of claim 21, wherein each zone of the plurality of zones comprises a respective flow rate, pressure, temperature, or any combination thereof, of the production, corresponding to increasing the production.
 25. The system of claim 24, wherein the one or more processors are configured to determine whether the measured flow rate, the measured pressure, the measured temperature, or any combination thereof, approximately matches the flow rate, pressure, temperature, or any combination thereof, by determining whether the respective measured flow rate, the measured pressure, the measured temperature, or any combination, at each zone of the plurality of zones approximately matches the respective flow rate, pressure, temperature, or any combination thereof, at the zone.
 26. The system of claim 25, wherein the second instruction is sent only to the one or more flow control devices, the one or more inflow control devices, or any combination thereof, in each zone of the plurality of zones where the measured flow rate, the measured pressure, the measured temperature, or any combination at the zone does not approximately match the respective flow rate, the pressure, the temperature, or any combination thereof, corresponding to increasing the production at the zone. 